System and Method for the Conditioning of Recirculated Exhaust Gas

ABSTRACT

A system, including: a recirculated exhaust gas conditioning loop that routes exhaust gas from a heat recovery steam generator to a turbine compressor inlet, wherein the recirculated exhaust gas conditioning loop includes an exhaust gas conditioning device that cools the exhaust gas and removes particulate matter from the exhaust gas, and a dehumidifier that dehumidifies the exhaust gas.

CROSS REFERENCE TO RELATED APPLICATIONS

This application claims the priority benefit of U.S. provisional patent application No. 61/970,766 filed Mar. 26, 2014 entitled SYSTEM AND METHOD FOR THE CONDITIONING OF RECIRCULATED EXHAUST GAS, the entirety of which is incorporated by reference herein.

TECHNOLOGICAL FIELD

The present description relates generally to gas turbine systems and, more particularly, to gas turbine driven power plants.

BACKGROUND

Gas turbine engines are used in a wide variety of applications, such as power generation, aircraft, and various machinery. Gas turbine engine generally combust a fuel with an oxidant (e.g., air) in a combustor section to generate hot combustion products, which then drive one or more turbine stages of a turbine section. In turn, the turbine section drives one or more compressor stages of a compressor section, thereby compressing oxidant for intake into the combustor section along with the fuel. Again, the fuel and oxidant mix in the combustor section, and then combust to produce the hot combustion products. These combustion products may include unburnt fuel, residual oxidant, and various emissions (e.g., nitrogen oxides) depending on the condition of combustion. Furthermore, gas turbine engines typically consume a vast amount of air as the oxidant, and output a considerable amount of exhaust gas into the atmosphere. In other words, the exhaust gas is typically wasted as a byproduct of the gas turbine operation.

SUMMARY

A system, including: a recirculated exhaust gas conditioning loop that routes exhaust gas from a heat recovery steam generator to a turbine compressor inlet, wherein the recirculated exhaust gas conditioning loop includes an exhaust gas conditioning device that cools the exhaust gas and removes particulate matter from the exhaust gas, and a dehumidifier that dehumidifies the exhaust gas.

The system can further include: a disengagement section, between the exhaust gas condition device and the dehumidifier that removes liquid from the exhaust gas, said liquid having been introduced by the exhaust gas conditioning device.

The exhaust gas conditioning device can include a vertical direct contact condenser with a spray column that generates a concurrent flow of the exhaust gas and a heat transfer liquid in a same downward direction.

The system can further include: the heat recovery steam generator, wherein an input to the recirculated gas conditioning loop is in fluid communication with a top back section of the heat recovery steam generator

The system can further include, prior to the exhaust gas conditioning device: a bypass stack that provides atmospheric venting of the exhaust gas; and a damper assembly that routes the exhaust gas to the bypass stack or the exhaust gas conditioning device.

The dehumidifier can include a flue gas condenser, wherein the flue gas condenser cools and dehumidifies the exhaust gas.

The system can further include: a protection stack that provides atmospheric venting of the exhaust gas downstream from the dehumidifier and prior to the turbine compressor inlet; and a damper assembly that routes the exhaust gas to the protection stack or the turbine compressor inlet, and downstream from the flue gas condenser.

A method, including: recirculating exhaust gas through a conditioning loop that routes exhaust gas from a heat recovery steam generator to a turbine compressor inlet, wherein the recirculating includes cooling, with an exhaust gas conditioning device, the exhaust gas, removing, with the exhaust gas condition device, particulate matter from the exhaust gas, and dehumidifying, with a dehumidifier, the exhaust gas.

The method can further include: removing, with a disengagement section between the exhaust gas conditioning device and the dehumidifier, liquid from the exhaust gas, said liquid having been introduced by the exhaust gas conditioning device.

The exhaust gas conditioning device can include a vertical direct contact condenser with a spray column, and the method can include generating a concurrent flow of the exhaust gas and a heat transfer liquid emitted from the spray column in a same downward direction.

The method can further include: controlling, with a computer, a damper assembly to route the exhaust gas to a bypass stack or to the exhaust gas conditioning device, wherein the bypass stack provides atmospheric venting of the exhaust gas prior to the exhaust gas reaching the exhaust gas conditioning device.

The method can further include: controlling, with a computer, a damper assembly to route the exhaust gas to a protection stack or the turbine compressor inlet, wherein the protection stack provides atmospheric venting of the exhaust gas downstream from the dehumidifier and prior to the turbine compressor inlet and downstream from the flue gas condenser.

BRIEF DESCRIPTION OF THE DRAWINGS

While the present disclosure is susceptible to various modifications and alternative forms, specific examples thereof have been shown in the drawings and are herein described in detail. It should be understood, however, that the description herein of specific examples is not intended to limit the disclosure to the particular forms disclosed herein, but on the contrary, this disclosure is to cover all modifications and equivalents as defined by the appended claims. It should also be understood that the drawings are not necessarily to scale, emphasis instead being placed upon clearly illustrating principles of the present technological advancement. Moreover, certain dimensions may be exaggerated to help visually convey such principles.

FIG. 1 is a non-limiting example of a system having a turbine-based service system coupled to a hydrocarbon production system.

FIG. 2 is a non-limiting example of the conditioning of recirculated exhaust gas.

FIG. 3 is flow chart of a non-limiting example of a process for the conditioning of recirculated exhaust gas.

FIG. 4 is a non-limiting example of a computer useable with the present technological advancement.

FIG. 5 is a flow chart of a non-limiting method for controlling the conditioning of recirculated gas.

DETAILED DESCRIPTION

Non-limiting examples of the present technological advancement are described herein. The invention is not limited to the specific examples described below, but rather, it includes all alternatives, modifications, and equivalents falling within the true spirit and scope of the appended claims.

In an effort to provide a concise description of these embodiments, all features of an actual implementation may not be described in the specification. It should be appreciated that in the development of any such actual implementation, as in an engineering or design project, numerous implementation-specific decisions are made to achieve the specific goals, such as compliance with system-related and/or business-related constraints, which may vary from one implementation to another. Moreover, it should be appreciated that such effort might be complex and time consuming, but would nevertheless be a routine undertaking of design, fabrication, and manufacture for those of ordinary skill having the benefit of this disclosure.

Detailed example embodiments are disclosed herein. However, specific structural and functional details disclosed herein are merely representative for purposes of describing example embodiments. Embodiments of the present technological advancement may, however, be embodied in many alternate forms, and should not be construed as limited to only the embodiments set forth herein.

The terminology used herein is for describing particular embodiments only and is not intended to be limiting of example embodiments. As used herein, the singular forms “a”, “an” and “the” are intended to include the plural forms as well, unless the context clearly indicates otherwise. The terms “comprises”, “comprising”, “includes” and/or “including”, when used herein, specify the presence of stated features, integers, steps, operations, elements, and/or components, but do not preclude the presence or addition of one or more other features, integers, steps, operations, elements, components, and/or groups thereof.

Although the terms first, second, primary, secondary, etc. may be used herein to describe various elements, these elements should not be limited by these terms. These terms are only used to distinguish one element from another. For example, but not limiting to, a first element could be termed a second element, and, similarly, a second element could be termed a first element, without departing from the scope of example embodiments. As used herein, the term “and/or” includes any, and all, combinations of one or more of the associated listed items.

Certain terminology may be used herein for the convenience of the reader only and is not to be taken as a limitation on the scope of the invention. For example, words such as “upper”, “lower”, “left”, “right”, “front”, “rear”, “top”, “bottom”, “horizontal”, “vertical”, “upstream”, “downstream”, “fore”, “aft”, and the like; merely describe the configuration shown in the FIGS. Indeed, the element or elements of an embodiment of the present invention may be oriented in any direction and the terminology, therefore, should be understood as encompassing such variations unless specified otherwise.

As discussed in detail below, the disclosed embodiments relate generally to gas turbine systems with exhaust gas recirculation (EGR), and particularly stoichiometric operation of the gas turbine systems using EGR. For example, the gas turbine systems may be configured to recirculate the exhaust gas along an exhaust recirculation path, stoichiometrically combust fuel and oxidant along with at least some of the recirculated exhaust gas, and capture the exhaust gas for use in various target systems. The recirculation of the exhaust gas along with stoichiometric combustion may help to increase the concentration level of carbon dioxide (CO₂) in the exhaust gas, which can then be post treated to separate and purify the CO₂ and nitrogen (N₂) for use in various target systems. The gas turbine systems also may employ various exhaust gas processing (e.g., heat recovery, catalyst reactions, etc.) along the exhaust recirculation path, thereby increasing the concentration level of CO₂, reducing concentration levels of other emissions (e.g., carbon monoxide, nitrogen oxides, and unburnt hydrocarbons), and increasing energy recovery (e.g., with heat recovery units). Furthermore, the gas turbine engines may be configured to combust the fuel and oxidant with one or more diffusion flames (e.g., using diffusion fuel nozzles), premix flames (e.g., using premix fuel nozzles), or any combination thereof. In certain embodiments, the diffusion flames may help to maintain stability and operation within certain limits for stoichiometric combustion, which in turn helps to increase production of CO₂. For example, a gas turbine system operating with diffusion flames may enable a greater quantity of EGR, as compared to a gas turbine system operating with premix flames. In turn, the increased quantity of EGR helps to increase CO₂ production. Possible target systems include pipelines, storage tanks, carbon sequestration systems, and hydrocarbon production systems, such as enhanced oil recovery (EOR) systems.

In particular, present embodiments are directed toward gas turbine systems, namely stoichiometric exhaust gas recirculation (EGR) systems including ultra-low emission technology (ULET) power plants. These systems generally include at least one gas turbine engine that is coupled to, and generates electrical power for, an electrical grid. For example, present embodiments include a ULET power plant having one or more electrical generators that convert a portion of the mechanical power provided by one or more EGR gas turbine engines into electrical power for delivery to the electrical grid.

With the foregoing in mind, FIG. 1 is a diagram of an embodiment of a system 10 having a hydrocarbon production system 12 associated with a turbine-based service system 14. As discussed in further detail below, various embodiments of the turbine-based service system 14 are configured to provide various services, such as electrical power, mechanical power, and fluids (e.g., exhaust gas), to the hydrocarbon production system 12 to facilitate the production or retrieval of oil and/or gas. In the illustrated embodiment, the hydrocarbon production system 12 includes an oil/gas extraction system 16 and an enhanced oil recovery (EOR) system 18, which are coupled to a subterranean reservoir 20 (e.g., an oil, gas, or hydrocarbon reservoir). The oil/gas extraction system 16 includes a variety of surface equipment 22, such as a Christmas tree or production tree 24, coupled to an oil/gas well 26. Furthermore, the well 26 may include one or more tubulars 28 extending through a drilled bore 30 in the earth 32 to the subterranean reservoir 20. The tree 24 includes one or more valves, chokes, isolation sleeves, blowout preventers, and various flow control devices, which regulate pressures and control flows to and from the subterranean reservoir 20. While the tree 24 is generally used to control the flow of the production fluid (e.g., oil or gas) out of the subterranean reservoir 20, the EOR system 18 may increase the production of oil or gas by injecting one or more fluids into the subterranean reservoir 20.

Accordingly, the EOR system 18 may include a fluid injection system 34, which has one or more tubulars 36 extending through a bore 38 in the earth 32 to the subterranean reservoir 20. For example, the EOR system 18 may route one or more fluids 40, such as gas, steam, water, chemicals, or any combination thereof, into the fluid injection system 34. For example, as discussed in further detail below, the EOR system 18 may be coupled to the turbine-based service system 14, such that the system 14 routes an exhaust gas 42 (e.g., substantially or entirely free of oxygen) to the EOR system 18 for use as the injection fluid 40. The fluid injection system 34 routes the fluid 40 (e.g., the exhaust gas 42) through the one or more tubulars 36 into the subterranean reservoir 20, as indicated by arrows 44. The injection fluid 40 enters the subterranean reservoir 20 through the tubular 36 at an offset distance 46 away from the tubular 28 of the oil/gas well 26. Accordingly, the injection fluid 40 displaces the oil/gas 48 disposed in the subterranean reservoir 20, and drives the oil/gas 48 up through the one or more tubulars 28 of the hydrocarbon production system 12, as indicated by arrows 50. As discussed in further detail below, the injection fluid 40 may include the exhaust gas 42 originating from the turbine-based service system 14, which is able to generate the exhaust gas 42 on-site as needed by the hydrocarbon production system 12. In other words, the turbine-based system 14 may simultaneously generate one or more services (e.g., electrical power, mechanical power, steam, water (e.g., desalinated water), and exhaust gas (e.g., substantially free of oxygen)) for use by the hydrocarbon production system 12, thereby reducing or eliminating the reliance on external sources of such services.

In the illustrated embodiment, the turbine-based service system 14 includes a stoichiometric exhaust gas recirculation (SEGR) gas turbine system 52 and an exhaust gas (EG) processing system 54. The gas turbine system 52 may be configured to operate in a stoichiometric combustion mode of operation (e.g., a stoichiometric control mode) and a non-stoichiometric combustion mode of operation (e.g., a non-stoichiometric control mode), such as a fuel-lean control mode or a fuel-rich control mode. In the stoichiometric control mode, the combustion generally occurs in a substantially stoichiometric ratio of a fuel and oxidant, thereby resulting in substantially stoichiometric combustion. In particular, stoichiometric combustion generally involves consuming substantially all of the fuel and oxidant in the combustion reaction, such that the products of combustion are substantially or entirely free of unburnt fuel and oxidant. One measure of stoichiometric combustion is the equivalence ratio, or phi (Φ), which is the ratio of the actual fuel/oxidant ratio relative to the stoichiometric fuel/oxidant ratio. An equivalence ratio of greater than 1.0 results in a fuel-rich combustion of the fuel and oxidant, whereas an equivalence ratio of less than 1.0 results in a fuel-lean combustion of the fuel and oxidant. In contrast, an equivalence ratio of 1.0 results in combustion that is neither fuel-rich nor fuel-lean, thereby substantially consuming all of the fuel and oxidant in the combustion reaction. In context of the disclosed embodiments, the term stoichiometric or substantially stoichiometric may refer to an equivalence ratio of approximately 0.95 to approximately 1.05. However, the disclosed embodiments may also include an equivalence ratio of 1.0 plus or minus 0.01, 0.02, 0.03, 0.04, 0.05, or more. Again, the stoichiometric combustion of fuel and oxidant in the turbine-based service system 14 may result in products of combustion or exhaust gas (e.g., 42) with substantially no unburnt fuel or oxidant remaining. For example, the exhaust gas 42 may have less than 1, 2, 3, 4, or 5 percent by volume of oxidant (e.g., oxygen), unburnt fuel or hydrocarbons (e.g., HCs), nitrogen oxides (e.g., NO_(X)), carbon monoxide (CO), sulfur oxides (e.g., SO_(X)), hydrogen, and other products of incomplete combustion. By further example, the exhaust gas 42 may have less than approximately 10, 20, 30, 40, 50, 60, 70, 80, 90, 100, 200, 300, 400, 500, 1000, 2000, 3000, 4000, or 5000 parts per million by volume (ppmv) of oxidant (e.g., oxygen), unburnt fuel or hydrocarbons (e.g., HCs), nitrogen oxides (e.g., NO_(X)), carbon monoxide (CO), sulfur oxides (e.g., SO_(X)), hydrogen, and other products of incomplete combustion. However, the disclosed embodiments also may produce other ranges of residual fuel, oxidant, and other emissions levels in the exhaust gas 42. As used herein, the terms emissions, emissions levels, and emissions targets may refer to concentration levels of certain products of combustion (e.g., NO_(X), CO, SO_(X), O₂, N₂, H₂, HCs, etc.), which may be present in recirculated gas streams, vented gas streams (e.g., exhausted into the atmosphere), and gas streams used in various target systems (e.g., the hydrocarbon production system 12).

Although the SEGR gas turbine system 52 and the EG processing system 54 may include a variety of components in different embodiments, the illustrated EG processing system 54 includes a heat recovery steam generator (HRSG) 56 and an exhaust gas recirculation (EGR) system 58, which receive and process an exhaust gas 60 originating from the SEGR gas turbine system 52. The HRSG 56 may include one or more heat exchangers, condensers, and various heat recovery equipment, which collectively function to transfer heat from the exhaust gas 60 to a stream of water, thereby generating steam 62. The steam 62 may be used in one or more steam turbines, the EOR system 18, or any other portion of the hydrocarbon production system 12. For example, the HRSG 56 may generate low pressure, medium pressure, and/or high pressure steam 62, which may be selectively applied to low, medium, and high pressure steam turbine stages, or different applications of the EOR system 18. In addition to the steam 62, a treated water 64, such as a desalinated water, may be generated by the HRSG 56, the EGR system 58, and/or another portion of the EG processing system 54 or the SEGR gas turbine system 52. The treated water 64 (e.g., desalinated water) may be particularly useful in areas with water shortages, such as inland or desert regions. The treated water 64 may be generated, at least in part, due to the large volume of air driving combustion of fuel within the SEGR gas turbine system 52. While the on-site generation of steam 62 and water 64 may be beneficial in many applications (including the hydrocarbon production system 12), the on-site generation of exhaust gas 42, 60 may be particularly beneficial for the EOR system 18, due to its low oxygen content, high pressure, and heat derived from the SEGR gas turbine system 52. Accordingly, the HRSG 56, the EGR system 58, and/or another portion of the EG processing system 54 may output or recirculate an exhaust gas 60 into the SEGR gas turbine system 52 via the recirculated exhaust gas conditioning system (REGCS) 100, while also routing the exhaust gas 42 to the EOR system 18 for use with the hydrocarbon production system 12. Likewise, the exhaust gas 42 may be extracted directly from the SEGR gas turbine system 52 (i.e., without passing through the EG processing system 54) for use in the EOR system 18 of the hydrocarbon production system 12.

The exhaust gas recirculation is handled by the EGR system 58 of the EG processing system 54. For example, the EGR system 58 includes one or more conduits, valves, blowers, exhaust gas treatment systems (e.g., filters, particulate removal units, gas separation units, gas purification units, heat exchangers, heat recovery units, moisture removal units, catalyst units, chemical injection units, or any combination thereof), and controls to recirculate the exhaust gas along an exhaust gas circulation path from an output (e.g., discharged exhaust gas 60) to an input (e.g., intake exhaust gas 60) of the SEGR gas turbine system 52. In the illustrated embodiment, the SEGR gas turbine system 52 intakes the exhaust gas 60 into a compressor section having one or more compressors, thereby compressing the exhaust gas 60 for use in a combustor section along with an intake of an oxidant 68 and one or more fuels 70. The oxidant 68 may include ambient air, pure oxygen, oxygen-enriched air, oxygen-reduced air, oxygen-nitrogen mixtures, or any suitable oxidant that facilitates combustion of the fuel 70. The fuel 70 may include one or more gas fuels, liquid fuels, or any combination thereof. For example, the fuel 70 may include natural gas, liquefied natural gas (LNG), syngas, methane, ethane, propane, butane, naphtha, kerosene, diesel fuel, ethanol, methanol, biofuel, or any combination thereof.

The SEGR gas turbine system 52 mixes and combusts the exhaust gas 60, the oxidant 68, and the fuel 70 in the combustor section, thereby generating hot combustion gases or exhaust gas 60 to drive one or more turbine stages in a turbine section. In certain embodiments, each combustor in the combustor section includes one or more premix fuel nozzles, one or more diffusion fuel nozzles, or any combination thereof. For example, each premix fuel nozzle may be configured to mix the oxidant 68 and the fuel 70 internally within the fuel nozzle and/or partially upstream of the fuel nozzle, thereby injecting an oxidant-fuel mixture from the fuel nozzle into the combustion zone for a premixed combustion (e.g., a premixed flame). By further example, each diffusion fuel nozzle may be configured to isolate the flows of oxidant 68 and fuel 70 within the fuel nozzle, thereby separately injecting the oxidant 68 and the fuel 70 from the fuel nozzle into the combustion zone for diffusion combustion (e.g., a diffusion flame). In particular, the diffusion combustion provided by the diffusion fuel nozzles delays mixing of the oxidant 68 and the fuel 70 until the point of initial combustion, i.e., the flame region. In embodiments employing the diffusion fuel nozzles, the diffusion flame may provide increased flame stability, because the diffusion flame generally forms at the point of stoichiometry between the separate streams of oxidant 68 and fuel 70 (i.e., as the oxidant 68 and fuel 70 are mixing). In certain embodiments, one or more diluents (e.g., the exhaust gas 60, steam, nitrogen, or another inert gas) may be pre-mixed with the oxidant 68, the fuel 70, or both, in either the diffusion fuel nozzle or the premix fuel nozzle. In addition, one or more diluents (e.g., the exhaust gas 60, steam, nitrogen, or another inert gas) may be injected into the combustor at or downstream from the point of combustion within each combustor. The use of these diluents may help temper the flame (e.g., premix flame or diffusion flame), thereby helping to reduce NO_(X) emissions, such as nitrogen monoxide (NO) and nitrogen dioxide (NO₂). Regardless of the type of flame, the combustion produces hot combustion gases or exhaust gas 60 to drive one or more turbine stages. As each turbine stage is driven by the exhaust gas 60, the SEGR gas turbine system 52 generates a mechanical power 72 and/or an electrical power 74 (e.g., via an electrical generator). The system 52 also outputs the exhaust gas 60, and may further output water 64. Again, the water 64 may be a treated water, such as a desalinated water, which may be useful in a variety of applications on-site or off-site.

Exhaust extraction is also provided by the SEGR gas turbine system 52 using one or more extraction points 76. For example, the illustrated embodiment includes an exhaust gas

(EG) supply system 78 having an exhaust gas (EG) extraction system 80 and an exhaust gas (EG) treatment system 82, which receive exhaust gas 42 from the extraction points 76, treat the exhaust gas 42, and then supply or distribute the exhaust gas 42 to various target systems. The target systems may include the EOR system 18 and/or other systems, such as a pipeline 86, a storage tank 88, or a carbon sequestration system 90. The EG extraction system 80 may include one or more conduits, valves, controls, and flow separations, which facilitate isolation of the exhaust gas 42 from the oxidant 68, the fuel 70, and other contaminants, while also controlling the temperature, pressure, and flow rate of the extracted exhaust gas 42. The EG treatment system 82 may include one or more heat exchangers (e.g., heat recovery units such as heat recovery steam generators, condensers, coolers, or heaters), catalyst systems (e.g., oxidation catalyst systems), particulate and/or water removal systems (e.g., gas dehydration units, inertial separators, coalescing filters, water impermeable filters, and other filters), chemical injection systems, solvent based treatment systems (e.g., absorbers, flash tanks, etc.), carbon capture systems, gas separation systems, gas purification systems, and/or a solvent based treatment system, exhaust gas compressors, any combination thereof. These subsystems of the EG treatment system 82 enable control of the temperature, pressure, flow rate, moisture content (e.g., amount of water removal), particulate content (e.g., amount of particulate removal), and gas composition (e.g., percentage of CO₂, N₂, etc.).

The extracted exhaust gas 42 is treated by one or more subsystems of the EG treatment system 82, depending on the target system. For example, the EG treatment system 82 may direct all or part of the exhaust gas 42 through a carbon capture system, a gas separation system, a gas purification system, and/or a solvent based treatment system, which is controlled to separate and purify a carbonaceous gas (e.g., carbon dioxide) 92 and/or nitrogen (N₂) 94 for use in the various target systems. For example, embodiments of the EG treatment system 82 may perform gas separation and purification to produce a plurality of different streams 95 of exhaust gas 42, such as a first stream 96, a second stream 97, and a third stream 98. The first stream 96 may have a first composition that is rich in carbon dioxide and/or lean in nitrogen (e.g., a CO₂ rich, N₂ lean stream). The second stream 97 may have a second composition that has intermediate concentration levels of carbon dioxide and/or nitrogen (e.g., intermediate concentration CO₂, N₂ stream). The third stream 98 may have a third composition that is lean in carbon dioxide and/or rich in nitrogen (e.g., a CO₂ lean, N₂ rich stream). Each stream 95 (e.g., 96, 97, and 98) may include a gas dehydration unit, a filter, a gas compressor, or any combination thereof, to facilitate delivery of the stream 95 to a target system. In certain embodiments, the CO₂ rich, N₂ lean stream 96 may have a CO₂ purity or concentration level of greater than approximately 70, 75, 80, 85, 90, 95, 96, 97, 98, or 99 percent by volume, and a N₂ purity or concentration level of less than approximately 1, 2, 3, 4, 5, 10, 15, 20, 25, or 30 percent by volume. In contrast, the CO₂ lean, N₂ rich stream 98 may have a CO₂ purity or concentration level of less than approximately 1, 2, 3, 4, 5, 10, 15, 20, 25, or 30 percent by volume, and a N₂ purity or concentration level of greater than approximately 70, 75, 80, 85, 90, 95, 96, 97, 98, or 99 percent by volume. The intermediate concentration CO₂, N₂ stream 97 may have a CO₂ purity or concentration level and/or a N₂ purity or concentration level of between approximately 30 to 70, 35 to 65, 40 to 60, or 45 to 55 percent by volume. Although the foregoing ranges are merely non-limiting examples, the CO₂ rich, N₂ lean stream 96 and the CO₂ lean, N₂ rich stream 98 may be particularly well suited for use with the EOR system 18 and the other systems 84. However, any of these rich, lean, or intermediate concentration CO₂ streams 95 may be used, alone or in various combinations, with the EOR system 18 and the other systems 84. For example, the EOR system 18 and the other systems 84 (e.g., the pipeline 86, storage tank 88, and the carbon sequestration system 90) each may receive one or more CO₂ rich, N₂ lean streams 96, one or more CO₂ lean, N₂ rich streams 98, one or more intermediate concentration CO₂, N₂ streams 97, and one or more untreated exhaust gas 42 streams (i.e., bypassing the EG treatment system 82).

The EG extraction system 80 extracts the exhaust gas 42 at one or more extraction points 76 along the compressor section, the combustor section, and/or the turbine section, such that the exhaust gas 42 may be used in the EOR system 18 and other systems 84 at suitable temperatures and pressures. The EG extraction system 80 and/or the EG treatment system 82 also may circulate fluid flows (e.g., exhaust gas 42) to and from the EG processing system 54. For example, a portion of the exhaust gas 42 passing through the EG processing system 54 may be extracted by the EG extraction system 80 for use in the EOR system 18 and the other systems 84. In certain embodiments, the EG supply system 78 and the EG processing system 54 may be independent or integral with one another, and thus may use independent or common subsystems. For example, the EG treatment system 82 may be used by both the EG supply system 78 and the EG processing system 54. Exhaust gas 42 extracted from the EG processing system 54 may undergo multiple stages of gas treatment, such as one or more stages of gas treatment in the EG processing system 54 followed by one or more additional stages of gas treatment in the EG treatment system 82.

At each extraction point 76, the extracted exhaust gas 42 may be substantially free of oxidant 68 and fuel 70 (e.g., unburnt fuel or hydrocarbons) due to substantially stoichiometric combustion and/or gas treatment in the EG processing system 54. Furthermore, depending on the target system, the extracted exhaust gas 42 may undergo further treatment in the EG treatment system 82 of the EG supply system 78, thereby further reducing any residual oxidant 68, fuel 70, or other undesirable products of combustion. For example, either before or after treatment in the EG treatment system 82, the extracted exhaust gas 42 may have less than 1, 2, 3, 4, or 5 percent by volume of oxidant (e.g., oxygen), unburnt fuel or hydrocarbons (e.g., HCs), nitrogen oxides (e.g., NO_(X)), carbon monoxide (CO), sulfur oxides (e.g., SO_(X)), hydrogen, and other products of incomplete combustion. By further example, either before or after treatment in the EG treatment system 82, the extracted exhaust gas 42 may have less than approximately 10, 20, 30, 40, 50, 60, 70, 80, 90, 100, 200, 300, 400, 500, 1000, 2000, 3000, 4000, or 5000 parts per million by volume (ppmv) of oxidant (e.g., oxygen), unburnt fuel or hydrocarbons (e.g., HCs), nitrogen oxides (e.g., NO_(X)), carbon monoxide (CO), sulfur oxides (e.g., SO_(X)), hydrogen, and other products of incomplete combustion. Thus, the exhaust gas 42 is particularly well suited for use with the EOR system 18.

The EGR operation of the turbine system 52 specifically enables the exhaust extraction at a multitude of locations 76. For example, the compressor section of the system 52 may be used to compress the exhaust gas 60 without any oxidant 68 (i.e., only compression of the exhaust gas 60), such that a substantially oxygen-free exhaust gas 42 may be extracted from the compressor section and/or the combustor section prior to entry of the oxidant 68 and the fuel 70. The extraction points 76 may be located at interstage ports between adjacent compressor stages, at ports along the compressor discharge casing, at ports along each combustor in the combustor section, or any combination thereof. In certain embodiments, the exhaust gas 60 may not mix with the oxidant 68 and fuel 70 until it reaches the head end portion and/or fuel nozzles of each combustor in the combustor section. Furthermore, one or more flow separators (e.g., walls, dividers, baffles, or the like) may be used to isolate the oxidant 68 and the fuel 70 from the extraction points 76. With these flow separators, the extraction points 76 may be disposed directly along a wall of each combustor in the combustor section.

Once the exhaust gas 60, oxidant 68, and fuel 70 flow through the head end portion (e.g., through fuel nozzles) into the combustion portion (e.g., combustion chamber) of each combustor, the SEGR gas turbine system 52 is controlled to provide a substantially stoichiometric combustion of the exhaust gas 60, oxidant 68, and fuel 70. For example, the system 52 may maintain an equivalence ratio of approximately 0.95 to approximately 1.05. As a result, the products of combustion of the mixture of exhaust gas 60, oxidant 68, and fuel 70 in each combustor is substantially free of oxygen and unburnt fuel. Thus, the products of combustion (or exhaust gas) may be extracted from the turbine section of the SEGR gas turbine system 52 for use as the exhaust gas 42 routed to the EOR system 18. Along the turbine section, the extraction points 76 may be located at any turbine stage, such as interstage ports between adjacent turbine stages. Thus, using any of the foregoing extraction points 76, the turbine-based service system 14 may generate, extract, and deliver the exhaust gas 42 to the hydrocarbon production system 12 (e.g., the EOR system 18) for use in the production of oil/gas 48 from the subterranean reservoir 20.

FIG. 2 is a non-limiting example of the conditioning of recirculated exhaust gas. Many challenges are associated with employing recirculated exhaust gas (EGR) as an alternative to an air intake for a gas turbine or similar equipment. The EGR should be cooled to a temperature that will not damage the gas turbine rotors and other associated components. Additionally, the EGR should be free of particulates as possible.

In this non-limiting examples, turbine exhaust gas 60 passes through HRSG 56, which reduces the temperature of the exhaust gas. Duct burners and reactions with catalyst beds located within HRSG 56 can contribute to soot and particulate formation in the exhaust gas 60. The HRSG 56 can be configured so that the exhaust gas 60 exits a top of the back end 56A of the HRSG 56. This configuration mitigates concerns of vapor accumulation in the region denoted by 56B. However, other configurations are useable with the present technological advancement.

Exiting the HRSG, a bypass stack damper 200 can route the turbine exhaust gas 60 to the atmosphere via bypass stack 202. Sensors may be at or near bypass stack damper 200. Such sensors may monitor temperature, water concentration, and/or particulate concentration, and communicate information to one or more computers that control the system shown in FIGS. 1 and 2. If temperature, water concentration, and/or particulate concentration is outside of acceptable ranges, then the computer can position the damper to cause the exhaust gas to be routed to the atmosphere. While temperature, water concentration, and particulate sensors are discussed, these are merely examples and sensors that monitor other criteria can be used.

If there is no reason to route the exhaust gas 60 to the atmosphere, then the computer can position the bypass stack damper 200 to route the exhaust gas 60 to recirculation ductwork, and then to the soot wash/cooling section 204.

The exhaust gas 60 can enter the soot wash/cooling section 204 downward. The soot wash/cooling section 204 includes spray column 204 a that sprays cold clean water downwards. Pipe line 206 carries cold clean water from a filtration system 230 (discussed below) and any make-up cold clean water (source not shown) than may be necessary. The cold clean water cools or desuperheats the exhaust gas 60 and washes the exhaust gas 60 of particulates. Spray column 204 a can be one or more jets, nozzles, or showerheads. While cold clean water is used as a heat transfer medium to cool the exhaust gas 60 in this embodiment, other liquids or coolants could potentially be used as the heat transfer medium. Desuperheats refers to the exhaust gas being cooled past its dew point.

In a non-limiting embodiment, a concurrent flow (e.g., exhaust gas and water both flowing in the same direction and downward) direct contact spray condenser forms a basis of the design to cool and remove particulates from the exhaust gas. The vessel that contains the soot wash/cooling section 204 can optionally include additional heat transfer media that will further cool the exhaust gas 60. Such additional heat transfer media include, but are not limited thereto, packing trays and surface condensers.

The soot wash/cooling section 204 also include water collector 208 a. Water collector 208 a collects warm dirty water at the bottom of soot wash/cooling section 204. Gravity causes the warm dirty water to collect in water collector 208 a as a result of the concurrent flow. A collection of drains, pipes, valves, and/or pumps 210 can then route the warm dirty water to a water filtration system 230.

Following the soot wash/cooling section 204, the exhaust gas enters disengagement section 212. The disengagement section 212 removes water/liquid droplets that could have been carried over from the soot wash/cooling section 204. The disengagement section 212 can include a single vane or combination of vanes in which the water/liquid and residual droplets are entrained and routed to water collector 208 b. In some configurations, water collectors 208 a and 208 b could be in fluid communication with each other, or a common water collector could service both the soot wash/cooling section 204 and disengagement section 212. Also, water collected by water collector 208 b can be routed to the water filtration system.

Following the disengagement section 212, the exhaust gas passes through blower 214. Blower 214 can be a fan that forces the exhaust gas through the recirculation transfer ductwork 216. The system in FIG. 2 depicts one blower, but the system can include multiple blowers positioned along the recirculation transfer ductwork 216 as needed.

Advancing through the recirculation transfer ductwork 216, the exhaust gas 60 next enters flue gas condenser 218. Flue gas condenser 218 can be formed of pipes with bars that increase the heated surface and transfer heat to cold clean water circulating through cold clean water pipe 220. Alternatively, the flue gas condenser can be a dehumidifier that includes a condensing coil. Flue gas condenser 218 can be controlled by the computer, with the use of appropriate temperature and/or humidity sensors, to further cool and/or dehumidify the exhaust gas to a predetermined temperature and/or humidity range that is suitable for the inlet to the compressor SEGR gas turbine system 52.

Following, the flue gas condenser 218, the exhaust gas flows to a second disengagement section 222 with water collector 208 c. The second disengagement section removes condensate produced in the FGC. Optionally, prior to the second disengagement section 222, another soot wash/cooling section could be employed.

Following the second disengagement section 222, the exhaust gas 60 flows to a protection stack damper 224 and protection stack 226. The computer can use one or more sensors to monitor the qualities of the exhaust or state of the SEGR gas turbine system 52, and control the damper to route the exhaust gas to the atmosphere if necessary. The protection stack 226 downstream of the second disengagement section 222 allows for protection of the SEGR gas turbine system 52 should any aspect of the exhaust gas fail to provide the desired water content, particulate concentration, and temperature. If the sensors and computer confirm that the water content, particulate concentration, and temperature of the exhaust gas 60 are within acceptable limits, then the computer can control the protection stack damper 224 to route the exhaust gas 60 to the inlet of the SEGR gas turbine system 52.

The water filtration system 230, referenced above, provides a means to clean and recycle water used in the systems of FIG. 2. Warm dirty water collected by water collectors 208 a and 208 b are passed through filters 232. Waste 234 is discarded. Warm clean water 236 is routed to plate and frame heat exchanger 238. Warm clean water from water collector 208 c is also routed via pipe 240 to the plate and frame heat exchanger 238. The plate and frame heat exchanger outputs cold clean water to pipe 206 that feeds the soot wash/cooling section 204 and to pipe 220 that cools the flue gas condenser 218. Elements 242 and 246 are an inlet from a coolant tank (not shown) and an outlet to the coolant tank, respectively.

FIG. 3 is flow chart of a non-limiting example of a process for the conditioning of recirculated exhaust gas. Step 302 includes recirculating exhaust gas through a conditioning loop that routes exhaust gas from a heat recovery steam generator to a turbine compressor inlet.

Step 304 includes controlling, with a computer, a damper assembly to route the exhaust gas to a bypass stack or to the exhaust gas conditioning device, wherein the bypass stack provides atmospheric venting of the exhaust gas. Step 306 includes cooling, with an exhaust gas conditioning device, the exhaust gas. Step 308 includes removing, with the exhaust gas condition device, particulate matter from the exhaust gas. Step 310 includes removing, with a disengagement section, liquid from the exhaust gas, said liquid having been introduced by the exhaust gas conditioning device. Step 312 includes cooling and dehumidifying the exhaust gas with a flue gas condenser. Step 314 includes controlling, with a computer, a damper assembly to route the exhaust gas to a protection stack or the turbine compressor inlet, wherein the protection stack provides atmospheric venting of the exhaust gas subsequent from the dehumidifier and prior to the turbine compressor inlet and downstream from the flue gas condenser.

FIG. 4 is a block diagram of a computer 400 that can be used to control the system(s) in FIGS. 1 and 2. A central processing unit (CPU) 402 is coupled to system bus 404. The CPU 402 may be any general-purpose CPU, although other types of architectures of CPU 402 (or other components of exemplary system 400) may be used as long as CPU 402 (and other components of system 400) supports the operations as described herein. Those of ordinary skill in the art will appreciate that, while only a single CPU 402 is shown in FIG. 4, additional CPUs may be present. Moreover, the computer 400 may comprise a networked, multi-processor computer that may include a hybrid parallel CPU/GPU system. The CPU 402 may execute the various logical instructions according to various teachings disclosed herein. For example, the CPU 402 may execute machine-level instructions for performing processing according to the operational flow described.

The computer 400 may also include computer components such as non-transitory, computer-readable media. Examples of computer-readable media include a random access memory (RAM) 406, which may be SRAM, DRAM, SDRAM, or the like. The computer 400 may also include additional non-transitory, computer-readable media such as a read-only memory (ROM) 408, which may be PROM, EPROM, EEPROM, or the like. RAM 406 and

ROM 408 hold user and system data and programs, as is known in the art. The computer 400 may also include an input/output (I/O) adapter 410, a communications adapter 422, a user interface adapter 424, and a display adapter 418.

The I/O adapter 410 may connect additional non-transitory, computer-readable media such as a storage device(s) 412, including, for example, a hard drive, a compact disc (CD) drive, a floppy disk drive, a tape drive, and the like to computer 400. The storage device(s) may be used when RAM 406 is insufficient for the memory requirements associated with storing data for operations of the present techniques. The data storage of the computer 400 may be used for storing information and/or other data used or generated as disclosed herein. For example, storage device(s) 412 may be used to store configuration information or additional plug-ins in accordance with the present techniques. Further, user interface adapter 424 couples user input devices, such as a keyboard 428, a pointing device 426 and/or output devices to the computer 400. The display adapter 418 is driven by the CPU 402 to control the display on a display device 420 to, for example, present information to the user regarding available plug-ins.

The architecture of system 400 may be varied as desired. For example, any suitable processor-based device may be used, including without limitation personal computers, laptop computers, computer workstations, and multi-processor servers. Moreover, the present technological advancement may be implemented on application specific integrated circuits (ASICs) or very large scale integrated (VLSI) circuits. In fact, persons of ordinary skill in the art may use any number of suitable hardware structures capable of executing logical operations according to the present technological advancement. The term “processing circuit” includes a hardware processor (such as those found in the hardware devices noted above), ASICs, and VLSI circuits. Input data to the computer 400 may include various plug-ins and library files. Input data may additionally include configuration information.

FIG. 5 illustrates a non-limiting method for controlling the conditioning of recirculated gas. The steps in FIG. 5 are not necessarily performed in the order recited, and some steps may be performed simultaneously with others.

In step 502, sensors are used to measure temperature, particulate concentration, humidity, and/or the operational status of equipment. In step 504, the computer compares the sensor readings to pre-established criteria and either controls bypass stack damper 200 to route the exhaust gas 60 to the atmosphere via bypass stack 202 or to route the exhaust gas 60 to soot wash/cooling section 204. In step 506, the computer 400 controls valves that cause cold clean water to be supplied to the spray column 204 a, which in turn can push the exhaust gas through disengagement section 212. In step 508, the computer 400 causes blower 214 to force the exhaust gas through the recirculation ductwork 216. In step 510, the computer 400 controls flue gas condenser to cool and/or dehumidify the exhaust gas 60 before passing through disengagement section 222. In step 512, sensors are used to measure temperature, particulate concentration, humidity, and/or the operational status of equipment. In step 514, the computer compares the sensor readings to pre-established criteria and either controls protection stack damper 224 to route the exhaust gas 60 to the atmosphere via protection stack 226 or to route the exhaust gas 60 to SEGR gas turbine system 52. In step 516, the computer 400 controls the water filtration system, along with any associated valves that control the flow water in various pipes of the system, to recycle water and supply it to the various components as depicted in FIG. 2.

This written description uses examples to disclose the invention, including the best mode, and also to enable any person skilled in the art to practice the invention, including making and using any devices or systems and performing any incorporated methods. The patentable scope of the invention is defined by the claims, and may include other examples that occur to those skilled in the art. Such other examples are intended to be within the scope of the claims if they have structural elements that do not differ from the literal language of the claims, or if they include equivalent structural elements with insubstantial differences from the literal language of the claims. 

1. A system, comprising: a recirculated exhaust gas conditioning loop that routes exhaust gas from a heat recovery steam generator to a turbine compressor inlet, wherein the recirculated exhaust gas conditioning loop includes an exhaust gas conditioning device that cools the exhaust gas and removes particulate matter from the exhaust gas, and a dehumidifier that dehumidifies the exhaust gas.
 2. The system of claim 1, further comprising: a disengagement section, between the exhaust gas condition device and the dehumidifier, that removes liquid from the exhaust gas, said liquid having been introduced by the exhaust gas conditioning device.
 3. The system of claim 1, wherein the exhaust gas conditioning device includes a vertical direct contact condenser with a spray column that generates a concurrent flow of the exhaust gas and a heat transfer liquid in a same downward direction.
 4. The system of claim 1, further comprising: the heat recovery steam generator, wherein an input to the recirculated gas conditioning loop is in fluid communication with a top back section of the heat recovery steam generator
 5. The system of claim 1, further comprising, prior to the exhaust gas conditioning device: a bypass stack that provides atmospheric venting of the exhaust gas; and a damper assembly that routes the exhaust gas to the bypass stack or the exhaust gas conditioning device.
 6. The system of claim 1, wherein the dehumidifier includes a flue gas condenser, wherein the flue gas condenser cools and dehumidifies the exhaust gas.
 7. The system of claim 1, further comprising: a protection stack that provides atmospheric venting of the exhaust gas downstream from the dehumidifier and prior to the turbine compressor inlet; and a damper assembly that routes the exhaust gas to the protection stack or the turbine compressor inlet, and downstream from the flue gas condenser.
 8. A method, comprising: recirculating exhaust gas through a conditioning loop that routes exhaust gas from a heat recovery steam generator to a turbine compressor inlet, wherein the recirculating includes: cooling, with an exhaust gas conditioning device, the exhaust gas, removing, with the exhaust gas condition device, particulate matter from the exhaust gas, and dehumidifying, with a dehumidifier, the exhaust gas.
 9. The method of claim 8, further comprising: removing, with a disengagement section between the exhaust gas conditioning device and the dehumidifier, liquid from the exhaust gas, said liquid having been introduced by the exhaust gas conditioning device.
 10. The method of claim 8, wherein the exhaust gas conditioning device includes a vertical direct contact condenser with a spray column, and the method comprises generating a concurrent flow of the exhaust gas and a heat transfer liquid emitted from the spray column in a same downward direction.
 11. The method of claim 8, further comprising: controlling, with a computer, a damper assembly to route the exhaust gas to a bypass stack or to the exhaust gas conditioning device, wherein the bypass stack provides atmospheric venting of the exhaust gas prior to the exhaust gas reaching the exhaust gas conditioning device.
 12. The method of claim 8, wherein the dehumidifying includes using a flue gas condenser.
 13. The method of claim 13, further comprising: controlling, with a computer, a damper assembly to route the exhaust gas to a protection stack or the turbine compressor inlet, wherein the protection stack provides atmospheric venting of the exhaust gas downstream from the dehumidifier and prior to the turbine compressor inlet and downstream from the flue gas condenser. 